Initial evaluation of the impact of post-combustion capture of carbon dioxide on supercritical pulverised coal power plant part load performance

Transcription

1 Fuel 86 (2007) Initial evaluation of the impact of post-combustion capture of carbon dioxide on supercritical pulverised coal power plant part load performance Hannah Chalmers *, Jon Gibbins Energy Technology for Sustainable Development Group, Mechanical Engineering Department, Imperial College, Exhibition Road, London SW7 2AZ, United Kingdom Received 2 October 2006; received in revised form 30 January 2007; accepted 30 January 2007 Available online 27 February 2007 Abstract Pulverised coal-fired plants often play an important role in electricity grids as mid-merit plants that can operate flexibly in response to changes in supply and demand. As a consequence, these plants are required to operate over a wide output range. This paper presents an initial evaluation of some potential impacts of adding post-combustion CO 2 capture on the part load performance of pulverised coalfired plants. Preliminary results for ideal cases analysed using a simple high-level model indicate that post-combustion CO 2 capture could increase the options available to power plant operators. In particular, solvent storage could allow higher effective plant load factors to be achieved to assist with capital recovery while still permitting flexible operation for grid support. A number of areas for more detailed analysis are identified. Ó 2007 Elsevier Ltd. All rights reserved. Keywords: Post-combustion CO 2 capture; Fossil-fired power plant flexibility; Part load performance 1. Introduction Successful implementation of carbon capture and storage (CCS) technologies should allow the continued use of fossil fuels in many applications, including power generation, but with significantly reduced carbon dioxide (CO 2 ) emissions. A range of engineering desk studies (e.g. a series of IEA Greenhouse Gas R&D Programme studies summarised in [1]) have predicted the costs and performance of power plants with CO 2 capture at full load. The published literature does not, however, contain any detailed assessments of the predicted impacts on part load performance of adding CO 2 capture to power plants. Fossil-fired plants have higher marginal operating costs than nuclear and most renewables, even when they operate * Corresponding author. Tel.: +44 (0) ; fax: +44 (0) address: hannah.chalmers@imperial.ac.uk (H. Chalmers). within CCS schemes with an associated reduction in any charges for CO 2 emissions. As a result, fossil-fired plants may be mid-merit and so may not run continuously at full load. Instead, their output will vary, partly in response to changes in supply or demand within the grid so that the quality and security of electricity supply is maintained. Understanding part load performance of these plants is important to determine how plant operation can be optimised within their operating environment. A number of other key factors also contribute to characterising the suitability of plant to act as flexible mid-merit plant including technical constraints, such as the ability of plant to startup, shutdown and ramp output up or down rapidly. Experience in the UK market suggests that the position of plants in the merit order can change significantly during the plant lifetime. Thus, the suitability of plants to operate as mid-merit should be assessed at the design stage, even if they are initially designed for base-load operation. Also, even at an early stage in a plant s life, appropriate use of /$ - see front matter Ó 2007 Elsevier Ltd. All rights reserved. doi: /j.fuel

2 2110 H. Chalmers, J. Gibbins / Fuel 86 (2007) various operating options for plants with CO 2 capture might improve the economic returns, compared to simple fixed-output operation. For example, there may be potential to vary capture rates in response to variable electricity and carbon prices. To fully evaluate this facility would require a detailed analysis of possible future electricity and carbon markets as well as the specific technical capabilities of the power plant and capture system, but some preliminary assessments are presented. This paper reports the results of an initial study on the flexibility of post-combustion CO 2 capture plants with a particular focus on potential impacts on power plant part load performance and operations for a pulverised coalfired plant. A simple model for plant off-design behaviour is developed and a series of ideal cases are used to consider possible plant performance curves. This model is also used to explore some alternative operating patterns for power plants with post-combustion CO 2 capture. Similar analysis could also be applied to other CO 2 capture technologies. However, it appears that plants with post-combustion CO 2 capture would be most able to take advantage of the variable operating procedures analysed here. Discussion of useful further work suggested by the initial analysis is also included. It should also be noted that much of this paper will focus on initial modelling of one particular aspect of CO 2 capture plant flexibility and on one type of capture plant. Many other options and potential impacts associated with developing CCS systems using power plants should also be subjected to further study. For example, the use of biomass co-firing at power plants with CO 2 capture allows CO 2 that was removed from the atmosphere by biomass as it grew to be placed into permanent geological storage [2]. It is likely that the level of implementation of these measures will depend on the policy framework, including any value attached to CO 2 reductions and, in the case of co-firing, the availability of renewable fuel. Also, it is important to understand how CO 2 transport and storage operations interact with power plant behaviour. It seems likely that any restrictions on short term operating patterns could be avoided by adopting operating procedures that allowed for some CO 2 buffering in the pipeline transport system, other interim storage or the use of a variable-flow storage site (e.g. disused gas reservoir, saline aquifer). The matching of CO 2 supply to demand and/or an appropriate combination of storage sites should therefore be considered carefully at an early stage of capture project development. 2. Post-combustion capture for power plants In all CCS schemes, CO 2 is collected from a large point source before it is treated and compressed for transport to safe geological storage. Post-combustion capture systems, as illustrated schematically in Fig. 1, are placed downstream of the combustion and other flue gas treatment processes. For coal-fired plants improved flue gas desulphurisation may be required to minimise the loss of solvent during the CO 2 capture process, but this is not necessary for gas-fired plants since they do not produce significant quantities of sulphur containing compounds in their flue gases. The CO 2 capture process for post-combustion capture consists of three stages. First, CO 2 is removed from the flue gas by absorption in a packed scrubber or absorber Fig. 1. Schematic diagram of post-combustion capture plant with optional solvent storage tanks.

3 H. Chalmers, J. Gibbins / Fuel 86 (2007) column (or other gas/liquid contactor). The rich solvent containing CO 2 is then heated in a reboiler and associated stripper column to release the CO 2 which is compressed, typically to 110 bar, for transport to a geological storage site. The regenerated solvent is now lean and can be recycled back to the absorber. Most post-combustion CO 2 capture processes discussed in the literature and considered closest to commercial deployment use amine-based solvents [3]. However, other options are also under consideration, including amino acid-based solvents and ammonia solutions [4]. The most energy-intensive aspects of post-combustion CO 2 capture processes are the supply of heat for solvent regeneration and, to a lesser extent with current solvents, shaft power for CO 2 compression. It is now generally accepted that the most efficient way to reheat rich solvent in the reboiler is using steam taken from the power cycle [5]. As such, this steam is no longer available for electrical power production and an associated decrease in steam cycle efficiency is observed. A range of operating modes might be possible for power plants with post-combustion CO 2 capture, particularly if solvent storage (where CO 2 - rich solvent is not regenerated immediately) is available, and these are discussed in later sections of this paper. In the ideal models which are discussed in this paper it is assumed that, as an initial approximation, simple relationships can be used to represent the CO 2 capture efficiency penalty across all loads. These models are based on a consideration of expected behaviour for key components of the base power plant and CO 2 capture unit. For example, it is expected that the energy penalty associated with abstracting steam from the steam cycle will vary with different loads since the steam mass flow through the low pressure turbine cylinders is altered by diverting steam to the CO 2 capture plant for solvent regeneration with an associated impact on turbine efficiency. Against this, however, is the likelihood that an absorber system operating at part load will have reduced steam consumption per unit of CO 2 captured, due to reduced heat and mass transfer resistances. Other potential changes in plant efficiency at varying loads should also be explored. For example, waste heat rejected in the CO 2 compression process should be used to provide heat where possible within the power cycle (e.g. replacing condensate heating in the steam cycle) [5]. AsCO 2 capture plant load is varied the potential for heat transfer between the capture plant and the power cycle could also vary, with associated impacts on power plant efficiency. Thus, one implicit assumption in the ideal analysis presented in this paper is that sufficient low grade heat for condensate heating is available from CO 2 compressor intercooling at all operating loads. Some other important considerations relate to the sizing of plant to handle variable flows associated with off-design and part load operation. These could include recycle rates adjusted to maintain stable operation in many elements of the CO 2 capture system, including compressor/dryer units and the absorber. The design of the absorber system for post-combustion capture should also be able to accommodate variations in the CO 2 capture process, including dayto-day changes such as changing inlet temperatures depending on ambient conditions. Where possible, appropriate provisions should also be made to allow improvements in CO 2 capture technology (in particular improved solvent formulations) to be utilised as they are developed. It is important to note that any consequential additional output can only be accommodated if the plant has been built to allow these changes in operation. For example, the alternator and turbine must be sized appropriately and, because less waste heat may be rejected from the CO 2 drying and compression system for condensate heating, low pressure turbine tappings may need to be included to allow subsequent installation of conventional condensate heaters. 3. Potential impacts of post-combustion capture on transient performance Although this paper concentrates on the steady-state part load performance of coal-fired power plants with post-combustion capture, it is also useful to have some understanding of the transient behaviour of plants as they change load. The primary areas of interest are plant startup, shutdown and load following. In the final case, the fossil-fired power plant output varies to help ensure that supply and demand within an electricity network remain balanced. In all cases, one important concern is whether power plant transient performance will be negatively affected by adding CO 2 capture since this could have an adverse affect on plant economics, particularly for midmerit plant where the ability to offer flexibility to the grid operator can provide an important revenue stream (e.g. by providing spinning reserve to the network where a plant operator is paid to operate the plant at part load so that additional capacity can be brought online very quickly by rapidly increasing plant output if there is a sudden increase in demand or reduction in supply from other sources such as wind generation). Identifying potential improvements to plant transient performance is therefore also important since it is possible that these could improve a power plant s economic case. Further work is required to better understand transient behaviour of power plants with CO 2 capture. However, in general, it is expected that post-combustion capture should not impose constraints on power plant start-up times since excess flue gas can be vented. However, since the steam cycle and CO 2 capture plant are integrated, the power plant output, power cycle efficiency and steam mass flow in some parts of the cycle will be determined, in part, by the volume of steam abstracted for solvent regeneration. Thus, some constraints to power plant start-up could occur depending on the ability of the plant to handle changed steam flows and power production. Also, in electricity markets where there is a cost associated with emitting CO 2, the cost of producing electricity can be significantly increased if CO 2

4 2112 H. Chalmers, J. Gibbins / Fuel 86 (2007) is not captured, with an associated increase in the cost of CO 2 emissions included in the cost of electricity. A possible need to vent CO 2 during start-up could be an important addition to start-up costs that would alter plant operators dispatch decisions, although (as discussed below) this may be avoidable with moderate amounts of solvent storage. For load following operations, one constraint added by CO 2 capture could be the ramp rate of the CO 2 compression system, although a dynamic simulation of compressor and process is required to accurately predict system behaviour and this is beyond the scope of this initial study. If there is some constraint on the ability of plants with CO 2 capture to follow load when compared to the plant without capture resulting from CO 2 compressor characteristics, it may also be possible to change the load for the CO 2 compression train at a different rate to the power plant by careful control of the amine scrubbing plant, particularly if solvent storage is possible. This area of plant operation is not well understood, however, and, as with start-up, the implications for CO 2 emissions and other areas of plant performance during the transient period where power plant and capture plant loads are varying, possibly independently, requires further study. One consequence might be that CO 2 capture rates would be reduced slightly during periods of rapidly increasing load and increased slightly during reducing load. However, there is obviously less scope for numerically large increases in CO 2 capture rates than for decreases. It is important to realise that it is expected that a number of areas of plant operation will not be fully understood until they are systematically investigated using full plant models or pilot and demonstration plants. For example, appropriate measures will be required to ensure that the steam used for solvent regeneration can provide heat within a relatively narrow band of acceptable temperatures across the plant operating range (i.e. be within a defined pressure range, although extraction pressures at the turbine can decrease slightly due to reduced pressure and temperature drops expected during part load operation of the amine plant) so that sufficient CO 2 will be released from the rich solvent in the reboiler, but the solvent itself will not decompose. While it is expected that steam supply pressures can be appropriately regulated, there is potential for some mismatch to occur when a boiler is operated under sliding pressure conditions to improve power plant ramp rates. Finally, it should also be noted that adding post-combustion capture may provide options that could improve plant load following characteristics. For example, by varying the volume of steam abstraction for solvent regeneration over very short timescales, output changes due to variations in the steam cycle and possibly CO 2 compressor power will be approximately additive to changes that can be affected by opening the main turbine control valve and drawing down on the stored thermal energy in the boiler at coal-fired power plants [6]. But the rapidly increased higher loads can also be sustained for much longer periods than when only the stored energy in the boiler is available, giving sufficient time to bring additional burners into service. 4. Preliminary quantitative analysis of part load performance One important step in quantifying the part load performance of power plants is determining plant efficiency and CO 2 emissions across the operating range. Earlier work undertaken by the authors to develop appropriate models to do this is outlined in [7]. In the current study, models for supercritical coal-fired power plant behaviour, including with post-combustion capture added, are refined. A part load performance curve for a pulverised coal-fired power plant with a supercritical steam cycle and no CO 2 capture is developed based on published sources [8,9]. Performance curves for a similar plant with post-combustion CO 2 capture are then estimated using a range of ideal cases that are quantified in this paper using the energy penalties listed in Table 1. Where possible, the performance of plants with CO 2 capture has been matched to a plant which has full load behaviour as reported in a detailed engineering study of post-combustion capture completed for the IEA Greenhouse Gas R&D Programme [3]. Also in line with this study, net plant efficiency is defined as net power out as a proportion of fuel heat input to the boiler. In these ideal cases, a number of anticipated real impacts of adding CO 2 capture have been ignored although, as outlined in Section 2, the cases chosen are based on the expected behaviour of some key components of the base power plant and CO 2 capture equipment. Also, it has been assumed that the primary fuel is used to provide all heat input to the power cycle for all loads and that the impact of start-up and shutdown costs on plant dispatch decisions can be ignored. As such, the results obtained may not fully represent the behaviour of real plants. However, they do provide indicative preliminary data to allow some possible CO 2 capture plant operating patterns to be compared. Table 1 Modelling of efficiency penalty for post-combustion capture at pulverised coal-fired power plants % Point penalty at full load Model for multiple CCS units on one site Model for single CCS unit on one site Steam for CO 2 separation 5 Constant % across whole operating range Constant % across whole operating range Power for CO 2 separation 1 Constant % across whole operating range Constant % across whole operating range CO 2 compression 3 Constant % across whole operating range Constant % from 75% to 100% CO 2 load Constant MW below 75% CO 2 load

5 H. Chalmers, J. Gibbins / Fuel 86 (2007) To gain some understanding of potential differences between ideal and real plants, it is useful to quantify the sensitivity of modelling results to key assumptions where possible. For example, at one extreme, if power plants can be fitted with multiple capture and compression units which can be adjusted in small steps (a likely situation for a multiple-unit station with multiple CO 2 compressors drawing from a common manifold and possibly also a common low pressure steam supply for the solvent reboilers), as a first approximation it can be assumed that a constant percentage efficiency penalty is applied by the CO 2 separation and compression processes across the plant operating range. This is based on the assumption that, for a given capture process with a particular fuel, the energy 1 penalty per unit of CO 2 captured (and hence per unit of fuel used) is constant and independent of the non-capture efficiency of the power plant to which the CO 2 capture equipment is fitted and that it remains constant for all loads (or that the various effects of part load operation tend to compensate, as discussed above). Thus the energy to capture the CO 2 per unit of fuel can be expressed as a (fixed) percentage of the fuel s heating value, with the same ratio of units as power plant efficiency. The following equation then defines the plant efficiency for a given fuel input: g CCS ¼ g noccs %penalty ð1þ where g CCS is the net plant efficiency for a given fuel input with CCS operating, g noccs is the net plant efficiency for a given fuel input without CCS operating and %penalty is the percentage points energy penalty for capture at 100% load. Although this is clearly an approximation, it can be justified by considering the behaviour of the capture scheme. For example, a typical CO 2 compressor system is likely to be capable of efficient turndown to approximately 75% of full flow at constant discharge pressure [10]. But if all units at a typical power plant site were fitted with CO 2 capture then a bank of compressors would be required to provide sufficient capacity for the whole plant and, if the compressors have a common suction manifold, then varying numbers of compressors can be used at any particular time. For example, at a power station where four CO 2 compressors were used in this way, the whole CO 2 compression system could have efficient CO 2 compression in the range from about 19% to 100% of full load. For the solvent-based capture process occurring in the scrubber and stripper columns, pump and fan loads might not decrease linearly with gas throughput. However, it seems likely that these effects could be offset by other changes for example, as noted above, some equipment, such as absorbers and reboilers, is expected to operate more effectively at part load. Where units cannot necessarily be adjusted in small steps or the use of multiple components cannot be applied to allow overall efficient plant turndown over a wide range (e.g. if CO 2 capture is fitted to a single stand-alone unit) the simple model above cannot be applied. In this case, if stable operation of CO 2 capture plant below the limiting loads is possible, it will only be able to occur with reduced efficiency. For example, stable operation of the CO 2 compression system will require flow recirculation. To give an indication of potential changes in plant performance, an alternative model for efficiency penalty is required. A worst case scenario could be that the power consumption would remain constant below the limiting load i.e. a constant MW efficiency penalty would be applied. In this case, the plant efficiency with CCS based on heat inputs to the power plant is then given below: g CCS ¼ g noccs ½%penalty load1 ðheat in load1 =heat in load2 ÞŠ ð2þ where g CCS is the net plant efficiency for a given fuel input with CCS operating, g noccs is the net plant efficiency for a given fuel input without CCS operating, %penalty load1 is the energy penalty associated with adding capture at the limiting load, load 1 is the limiting load (minimum load at which efficient part load performance occurs) and load 2 is the lower load at which efficiency is being calculated. Using off-design efficiency curves for plant without capture based on published literature [8,9], efficiency curves for the plant operating range can be plotted. Fig. 2 illustrates some typical curves for the ideal cases defined above. 1 The term energy penalty is in common usage although it would be more accurately named the electricity penalty since it represents the lost electricity output due either to direct consumption by capture-related equipment (e.g. compressors, circulating pumps) or to reductions in steam turbine output due to steam abstraction. The heat transfer from the steam in the solvent reboiler is, however, much higher, typically around three times the reduction in electricity output due to steam abstraction (after heat integration is applied). Fig. 2. Part load efficiency curves for supercritical coal-fired plant with post-combustion capture using an amine-based solvent and supercritical coal-fired plant without CO 2 capture.

6 2114 H. Chalmers, J. Gibbins / Fuel 86 (2007) Fig. 3. Part load CO 2 emissions for supercritical coal-fired plant with post-combustion capture using an amine-based solvent and supercritical coal-fired plant without CO 2 capture. CO 2 emissions profiles for different technologies can also be calculated and these are shown in Fig. 3 based on coal CO 2 emissions of 91 kg CO 2 /GJ thermal (LHV basis), in line with assumptions for a world-traded Australian thermal coal used in a recent IEA Greenhouse Gas R&D Programme study on post-combustion capture [3]. The CO 2 capture efficiency is assumed to be 85%, although at real plants it is expected that this would be increased or decreased within limits set by the equipment, ambient conditions, etc., to maximise the net revenue. condensate heating if a full complement of conventional condensate heaters is not fitted) when CO 2 is vented imply that optimum efficiency may not be obtained in both the capture and non-capture cases, particularly if capital costs are to be minimised. However, this is not quantified for the ideal models reported in this paper. Instead it is assumed that when all CO 2 produced by the power plant is vented, the efficiency of the plant returns to that of a plant without CO 2 capture as defined in Fig. 2. It is expected that CO 2 venting in some form should be an option for all power plants with post-combustion CO 2 capture without significant additional capital expenditure beyond the extra capacity required directly in the LP turbine, condenser, alternator/switchgear, etc. In some cases, this expenditure may not be additional above the baseline plant specification, depending on the attitude of the power plant purchaser to reliability, availability, maintainability and operability. For cases where additional capital expenditure is required, appropriate long-run economic analysis is required to determine whether this capital expenditure can be justified by expected profits associated with venting CO 2 under appropriate economic conditions (and within the limits imposed by any environmental legislation). Some difficulties associated with completing analysis of this kind are identified and discussed in Section 7. Defining and checking data for long-run economic analysis should often involve appropriate analysis of short-run costs and revenues. For example, for the ideal models defined in this study, the cost of operating the base case capture plant defined in Figs. 4 and 5 (see Table 2 and the next section for an outline definition of all cases shown 5. Outline of potential for avoiding capture energy penalty by venting carbon dioxide One option for significantly improving the flexibility of fossil-fired power plants with CO 2 capture added is to identify options for changes in operating procedures, in some cases with some associated additional expenditure. For post-combustion capture plants, it is expected that the capture energy penalty can be almost entirely avoided by stopping CO 2 capture and venting the CO 2 in the flue gases. This would avoid the need for steam abstraction and compressor and amine plant ancillary power consumption, assuming that the balance of plant is appropriately sized to handle the increased steam flow in the low pressure steam turbine cylinder and condenser and the additional power available to send out (or alternatively the fuel input could be reduced in line with balance of plant constraints, but this does not make maximum use of most of the capital assets in the plant). For real plants, changes in the power cycle (e.g. steam flow to the low pressure turbine cylinders and the availability of heat from the CO 2 capture plant for Fig. 4. Part load efficiency curves for options for supercritical coal-fired plant with amine-based post-combustion capture compared to supercritical coal-fired plant without CO 2 capture.

7 H. Chalmers, J. Gibbins / Fuel 86 (2007) Fig. 6. Decision diagram for choice between operating plant with CO 2 capture or with CO 2 vented assuming maximum fuel input. Fig. 5. Part load CO 2 emissions curves for options for supercritical coalfired plant with amine-based post-combustion capture compared to supercritical coal-fired plant without CO 2 capture. Table 2 Different options for power plant operation with post-combustion capture Case Description Base case (capture) 85% of CO 2 produced captured using postcombustion process and rich solvent regenerated immediately Vent all CO 2 As capture base case, but with capture plant not operating. Thus net MW out increased for all loads since no capture energy penalty if balance of plant has appropriate capacity, but also higher CO 2 emission Store 85% CO 2 as produced Extra regeneration As capture base case, but with capture plant storing rich solvent to be regenerated later. Thus net MW out increased for all %loads, subject to any balance of plant restrictions. There is still a small capture energy penalty (e.g. for absorber tower pressure loss and solvent pumping, taken as 1% of fuel LHV for this analysis), but also low CO 2 emissions As capture base case, but with an additional volume of solvent regeneration (i.e. all CO 2 from current production captured with rich solvent regenerated immediately, but rich solvent flow rate increased by adding solvent from storage tank) on these figures) at full load of 750 MW for 1 h is around 15,300 plus any cost associated with emitting 105 tco 2 during those operations. If that plant was to vent CO 2 then the full load would increase to 921 MW with an associated operating cost of around 10,800/h (a reduction compared to operating with CO 2 capture since variable costs associated with CO 2 capture are avoided) and CO 2 emissions of approximately 700 tco 2 /h. Fig. 6 shows the variation in break-even cost where plant operation would switch from full load operations with CO 2 capture running to venting CO 2 at the increased full load available when only these options are available, based on analysis of short-run marginal costs and revenues. Clearly, the relative profitability of these operating options is dependent on both the selling price of electricity and the CO 2 price. When CO 2 prices increase, the breakeven point in terms of electricity selling price required for the plant to switch from CO 2 capture to venting is also increased. For low CO 2 prices a negative break-even electricity selling price is reported indicating that when CO 2 prices are low (below 7.50/tCO 2 ) the plant would always vent CO 2 regardless of the electricity selling price, unless other constraints (e.g. environmental law) required the plant to operate with CO 2 capture. This result can be explained by noting that when the CO 2 price is low, a plant venting CO 2 does not experience a significant financial penalty for emitting increased volumes of CO 2 and also that it is significantly cheaper to operate the plant without CO 2 capture if there is no significant financial penalty or other constraint on high CO 2 emissions. In particular, the variable operating and maintenance costs associated with CO 2 capture, storage and transport process are avoided when CO 2 is vented, as are the effects associated with decreased plant efficiency when CO 2 capture is used. The results reported here are generally in agreement with previous work at Imperial College [6] which concluded that CO 2 venting could be an attractive option for coal-fired plants with amine-based CO 2 capture when /MWh electricity prices are 2 3 times higher than /tco 2 prices. Although, a much lower electricity price is required to justify CO 2 venting at low CO 2 prices, for the ideal cases modelled in this paper this rule of thumb is accurate for CO 2 prices of around 20/tCO 2 and above.

8 2116 H. Chalmers, J. Gibbins / Fuel 86 (2007) As discussed above, some CO 2 venting should be an option available for all plants with post-combustion CO 2 capture. However, for plants to fully exploit potential additional revenue associated with venting CO 2 in certain conditions (e.g. extreme price spikes associated with periods of high demand such as cold snaps during winter), some areas of plant including the low pressure turbine, condenser and generator will require appropriate design to accommodate the large variation in flows associated with venting CO 2 and hence not abstracting steam from the steam cycle. For the base case assumptions chosen for this study (including a CO 2 price of 25/tCO 2 as outlined in the Section 6.2 below) it seems likely that pulverised coal-fired plants fitted with post-combustion CO 2 capture would not routinely vent CO 2 if other coal capacity was available since the marginal cost of electricity is higher than for the coal-fired plants operating with CO 2 capture. This also implies that significant additional capital expenditure to allow the power plant to operate at maximum load when CO 2 is not captured may not be justified. However, if these modifications are partly justified by other considerations (e.g. plant reliability) then venting of CO 2 could be a useful additional operating option. In the case outlined in this paper, when CO 2 is vented the maximum output from the plant is increased by nearly 200 MW. Thus, if electricity prices were high and other additional generation options were limited, the increased revenue associated with this additional capacity could be sufficient to justify venting CO 2 rather than operating with CO 2 capture. 6. Outline of potential for shifting capture energy penalty by storing carbon dioxide 6.1. Technical outline of solvent storage requirements It is also possible that CO 2 could be captured continuously but that most of the energy penalty associated with CO 2 capture could be incurred at some other time if solvent storage tanks are used between the CO 2 scrubber and stripper columns in the capture plant, as shown in Fig. 1. In this case power plants could then operate for several hours with CO 2 in the flue gas removed in the stripper column as in base case operation but with the energy-intensive solvent regeneration and CO 2 compression processes left until later. The rich solvent containing CO 2 leaves the scrubber as normal and is temporarily stored in solvent storage tanks, avoiding the majority of the energy penalty for the amine capture process, which is incurred as a result of abstracting steam from the steam cycle and compressing CO 2. Some time later, typically when lower electricity selling prices apply so the plant output is less valuable, the rich stored solvent would be regenerated by adding it to the normal solvent stream being produced due to plant operations. Table 2 summarises some possible operating conditions for a power plant with post-combustion capture, including some operating modes that would be made available by using solvent storage. Again, the quantitative analysis reported here is restricted to ideal cases where a constant percentage energy penalty for CO 2 capture is assumed across the power plant operating range. It is also assumed that for regeneration of stored solvent the energy penalty is increased directly in proportion to the volume of solvent regenerated, again neglecting changes in capture system and power cycle performance associated with changing steam mass flows and other cycle integration effects. Figs. 4 and 5 show off-design efficiency and CO 2 emissions curves for ideal cases of the options listed in Table 2, compared with the single operating curve available for plants without CO 2 capture. For illustrative purposes, the maximum load and operating range for the base case capture and non-capture plants have been assumed to be equal. Different operating possibilities for the plant with CO 2 capture are shown by curves which have an identical range of fuel inputs compared to the base case plant with CO 2 capture but different MW sent out. The addition of solvent storage tanks, the purchase of more solvent and the likely provision of additional capacity in balance of plant components to allow extra power to be generated and exported would require further capital expenditure. Depending on market conditions this outlay could be justified by an increase in plant revenues associated with improved plant flexibility and an associated ability to offer ancillary services to the electricity network operator and this is discussed further in the next section. For example, solvent storage could provide increased plant capacity (i.e. reserve) at times of high electricity demand. In this case, the day/night price differential for electricity selling price would be important to allow a comparison between the value of additional output generated in periods when solvent was stored and the value of output that would be unavailable when stored solvent is regenerated later Analysis of potential uptake of solvent storage based on short-run marginal costs A number of analytical methods are available to explore the potential uptake of the additional power plant operating options with post-combustion capture which are discussed above. This section will outline a method which uses short-run marginal cost (SRMC) of electricity, i.e. not long-run marginal cost (LRMC) and levelised costs, to explore expected power plant dispatch options. SRMC includes only those costs which are incurred to run a plant which has already been built mostly fuel, the cost of obtaining carbon credits for CO 2 emissions and variable operating and maintenance costs, although these are only significant for plants operating with post-combustion capture. In contrast, analysis with LRMC would take into account all plant costs, including paying back initial capital expenditure and fixed operating and maintenance costs. One important plant characteristic which is determined by SRMC, but critical in correctly estimating LRMC, is

9 H. Chalmers, J. Gibbins / Fuel 86 (2007) the load factor which indicates how many operating hours are achieved by the plant in a given time period. Once a plant has been built, the decisions on whether a plant should be run or not (i.e. dispatched) will be determined by analysis of projected short-term costs and revenues. If short-term revenues a larger than short-term costs then the plant will run. If the converse is true then the plant will not run. Clearly, the result of this analysis gives the plant load factor. One useful approach to provide an initial analysis of power plant operating decisions is to treat SRMC as an indicator of the break-even electricity price at which power plant operators will dispatch the plant. Since, by definition, SRMC does not allow any comparison of capital expenditure to establish different power plants on the grid, it cannot be used for a full analysis of power plant economic performance. However, understanding the power plant dispatch behaviour, which is strongly dependant on SRMC, is a necessary precursor to provide input assumptions required for analysis based on LRMC. As well as identifying a projected load factor, as discussed above, if assumptions for analysis of long-run analysis are underpinned by appropriate short-run analysis then this load factor should also be set in the context of a realistic set of price assumptions (including fuel and carbon) which are expected to lead to that operating pattern. Also, as outlined in following sections, short-run analysis can be used to indicate expected net short-term revenues (i.e. plant earned income which remains to contribute towards paying off capital etc once short-run costs included in the SRMC have been taken into account) for different operating patterns, such as a full cycle of solvent storage with associated solvent regeneration, which must be properly understood for an accurate analysis of plant long-run economic performance to be carried out. Fig. 7 illustrates the basic SRMC of electricity generation for each of the processes listed in Table 2. It is assumed that all variable operation and maintenance costs associated with the use of amine solvent should be included in the SRMC for solvent storage and that the transport cost is included in the SRMC for plant operation when CO 2 is produced, i.e. the cost of transport for CO 2 captured when solvent is stored is assumed to be included in the SRMC of regenerating that solvent, not in the SRMC for power plant operation with solvent storage. Although a comparison of the SRMC with the electricity selling price is often sufficient to indicate whether a plant should run or not (although in reality with some additional considerations including the impacts of start-up and shutdown fuel costs and impacts on plant component life, etc.) in the case of solvent storage and regeneration, as noted above, it may be more useful to consider the costs associated with a whole cycle including storage and regeneration, since the processes are, by definition, coupled. Although a loss may be made if electricity prices are low when solvent is regenerated (e.g. overnight), this could be offset by additional revenue associated with having the capability to Fig. 7. Basic SRMC for options for supercritical coal-fired plant with amine-based post-combustion capture compared to supercritical coal-fired without CO 2 capture. store solvent when electricity prices are much higher (e.g. during the day and, in particular, during any peaks which occur). This additional revenue can, however, unambiguously be assigned to the SRMC cost calculations for running periods when solvent is being regenerated, since it arises solely as a consequence of undertaking that solvent regeneration. The break-even cost for these paired processes of solvent storage and regeneration, can be found and expressed by a number of methods. This study proposes the use of an adjusted SRMC for one part of the storage/regeneration cycle which gives the break-even cost for one operation once the profit/loss associated with the other part of the cycle is known (or assumed/calculated from appropriate assumptions for the purposes of further exploratory analysis). For example, revenues gained from an assumed period of solvent storage are taken into account to find selling prices for electricity during periods of additional regeneration that would allow operating costs from the whole solvent/regeneration cycle to be recovered. As with the nonstorage cases, this analysis considers only marginal costs, so does not indicate the selling price for electricity that would be required to pay back the additional capital investment required for the construction of solvent storage facilities and for any additional plant modification nor, as an offset, any benefit from an increased load factor in reducing the required selling price per kwh to recover the capital investment in the rest of the plant. Basic marginal costs for running the plant while storing and regenerating additional solvent, including the same elements as cases without solvent storage, can be calculated as

10 2118 H. Chalmers, J. Gibbins / Fuel 86 (2007) shown in Fig. 7. The profits obtained during periods when solvent is stored can also be calculated, assuming that market conditions to determine profits can be known, or reasonably assumed as part of the analytical process. For a given plant output during additional solvent regeneration, the time required for regeneration of all stored solvent can also be calculated given an assumed rate of additional solvent regeneration. The adjusted SRMC for solvent regeneration is then defined by Eq. (3). Plant operators could also decide to regenerate solvent at a non-constant output power and/or solvent regeneration rate. In such cases, Eq. (3) should be appropriately adapted by summing operational costs and respective energy output under various different conditions: adjusted SRMC regen ¼ðopcost regen profit storage Þ=ðload regen time regen Þ ð3þ where adjusted SRMC is for the period when solvent is regenerated at a given plant output and regeneration rate, load regen is the selected output capacity in MW (or kw, etc.) from the plant during the period of solvent regeneration, time regen is the time required to allow for regeneration of all stored solvent given a selected load regen for the plant regenerating solvent and rate of additional regeneration, opcost regen is the basic cost of operation for time regen in or p given the plant operating conditions (e.g. rate of solvent regeneration) and profit storage is the profit obtained during the period while solvent is stored for later regeneration in or p (considering the solvent storage operation in isolation for the purposes of analysis). For the ideal cases shown in Fig. 8, maximum plant output is set to 750 MW for the non-capture plant and the base case plant with CO 2 capture. Coal price is chosen as 1.4/GJ in accordance with the central value in other ongoing work at Imperial [11] and the carbon price is set to an illustrative level of 25/tCO 2 so that the analysis represents a situation where some CCS schemes are expected to be commercially viable as a result of the value associated with avoiding CO 2 emissions. An illustrative cost of 5.5/tCO 2 for CO 2 transport and storage in an offshore aquifer [11] is also included, although it is not yet clear whether this cost would necessarily be included in the cost of electricity for all projects. Fig. 8 shows the adjusted SRMC for regeneration for various possible plant operating conditions. For the cases with solvent storage, it is assumed that solvent storage occurs with a plant operating at full load of 921 MW. Two electricity prices during solvent storage operations are considered: 3.4 p/kwh (i.e. 1 p/kwh higher than the SRMC of generation for the base case plant with CO 2 capture operating with continuous regeneration of produced CO 2 at full load) and 4.4 p/kwh (i.e. a further 1 p/kwh above the previous case). The times shown are for complete regeneration of stored solvent with continuous operation of the power plant with the given additional regeneration configuration (rate of additional generation and location Fig. 8. Adjusted SRMC for two plants with same fuel inputs and different operating patterns for CO 2 capture plant operating with solvent storage. within power plant operating range i.e. full load, minimum stable generation or somewhere between these extremes). As outlined above, during periods of additional solvent regeneration plant efficiency will be decreased further than with base case CO 2 capture operations resulting in reduced plant efficiency with an associated increase in fuel use and also a slight increase in CO 2 emissions. Although this results in a higher basic SRMC of electricity generation for the period of additional solvent regeneration than for the base case with CO 2 capture, the adjusted SRMC for electricity generated with additional solvent regeneration, which takes into account profits from the associated period of solvent storage, can still be lower than for plants without solvent storage. Thus, under some conditions, it is expected that solvent storage could be used on a regular basis to improve plant short-run economic performance by storing solvent at times of high demand (allowing the plant to generate additional revenues as a result of the high electricity prices associated with periods of high demand) and then regenerating additional solvent at times of lower demand when electricity prices will also be lower Analysis of potential uptake of solvent storage based on net revenues and short-run profits Although the adjusted SRMC data reported here is useful since it gives a single parameter to compare different plant operating options on a short-run cost basis and, addi-

11 H. Chalmers, J. Gibbins / Fuel 86 (2007) tionally, requires relatively few assumptions in generating the data used for comparison, it is important to remember that conclusions based on Fig. 8 do not take into account the possibility that plants without solvent storage may not run during off peak periods, when a plant with storage could still be run advantageously to regenerate solvent, since the value associated with solvent storage generates sufficient additional income to offset the otherwise uneconomic low electricity price. As such, further analysis which takes account of this operating decision is required for a more complete understanding of the conditions under which solvent storage could be economically attractive on a short-run basis. It is expected that these considerations could be included within an adjusted SRMC approach. However, this study uses direct calculation and comparison of net revenues for different plant operating patterns to establish which market and plant operating conditions provide environments which provide a net increase in shortrun revenue (which is plant income left to cover capital costs and other long-run costs once short-run costs have been taken into account). Although this method requires additional assumptions, which reduce generality of the conclusions reached, it provides clearer results to illustrate the potential profits and losses associated with solvent storage and regeneration operations for the particular examples which are analysed. Fig. 9a and b plot the additional net short-run revenue associated with solvent storage and regeneration for the conditions used for Fig. 8 and electricity prices during solvent regeneration of 2.39 p/kwh (i.e. the SRMC of generation for the base case plant with CO 2 capture operating with continuous regeneration of produced CO 2 at full load) and 2.89 p/kwh (i.e. 0.5 p/kwh above the previous case). The net increase (or loss) is based on comparison with a case where the same fuel input is used at a CO 2 capture plant without solvent storage. A clear difference in the pattern of results is obtained when the two cases are compared since for the lower electricity price during regeneration the base CO 2 capture plant does not run (or if it did, it would generate no net short-run net revenue since 2.39 p/kwh is the break-even cost for full load operation for this plant in this study), whereas with the higher electricity price it does. In particular, for cases where a 2.39 p/kwh electricity price during solvent regeneration is assumed, net additional revenue reduces at lower loads directly reflecting the increased adjusted SRMC for part load operation, with a constant net revenue obtained from the plant operating without solvent storage since it only generates a net revenue during solvent storage operations (and maximum fuel input is assumed for all solvent storage cases used in this study). When the electricity price is assumed to be 2.89 p/ kwh both plants operate during the period when additional solvent is regenerated at the plant operating with solvent storage. Both plants have increased adjusted SRMC at part load and, for the ideal cases considered here, the change in adjusted SRMC seen for both cases is such that a constant change in net short-term revenue across all loads is calculated for each case analysed here. If a similar result Fig. 9. Gain (or loss) in short-run net revenue associated with solvent storage compared to a base case CO 2 capture plant with the same fuel input (a) for electricity price of 2.39 p/kwh during additional solvent regeneration and (b) for electricity price of 2.89 p/kwh during additional solvent regeneration.